The present invention relates generally to methods for fracturing subterranean formations having tight lenticular gas sands or multiple pay sands and more particularly to a fracturing method that allows one zone of the formation to be fractured while simultaneously flowing back previously placed stimulation and/or fracture fluids from one or more other zones in the formation.
Many subterranean formations containing hydrocarbon reservoirs suffer from the problem of having insufficient permeability or productivity to enable the hydrocarbons to be recovered at the surface in an effective and economical manner. A number of techniques have been developed to increase the permeability or productivity of these formations. The most common techniques include hydraulically fracturing the subterranean formation and/or chemically stimulating the formation.
Hydraulic fracturing commonly involves injecting fluids into the formation at sufficiently high pressures to cause the formation to fracture. The fractures are then injected with a granular material known as a proppant, which may include sand, ceramic beads or other similar material. The proppants hold the fracture open after the pressure is released. The proppant-filled fractures create a higher permeability flow-path for the hydrocarbons to follow from the reservoir to the wellbore than that occurring naturally in the subterranean formation. Chemical stimulation techniques involve pumping certain chemicals into the formation, such as acid-based fluids, that etch away a path in the formation through which the hydrocarbons can flow or otherwise alter the properties of the formation so as to enhance its permeability.
After the flow paths have been created, regardless of the technique, the treatment fluids that have been injected into the formation must be recovered. The treatment fluids are recovered for a number of reasons. For one, some of these treatment fluids are expensive and can be reused in other fracturing and/or stimulating other wellbores. Furthermore, it is believed that certain treatment fluids, especially water-based treatment fluids, left in the formation for extended periods of time can actually inhibit the flow of hydrocarbons rather than enhance it. This damage can be compounded by time and depth of fluid penetration. The process reduces and in some instances prohibits the hydrocarbons from flowing toward the wellbore. This condition is known as imbibement. The step of producing the fracture or stimulation fluid to the surface is known as “flow back.”
In conventional fracture methods, the fracture/stimulation fluids are not circulated back to the surface until after the fracture/stimulation procedure has been completed, which can sometimes take several days or even weeks if multiple zones are being fractured using conventional fracturing/stimulation techniques. After that period of time, the amount of imbibement can be significant.
In addition to the ill effects of imbibement, which are caused using conventional fracture/stimulation methods to complete a well, the time lost associated with these techniques is significant and can result in potentially significant lost revenue. This is because each of the steps associated with fracturing/stimulating a multi-zone formation have conventionally been performed separately. Furthermore, conventional fracturing/stimulation techniques require multiple trips into and out of the well of downhole tools to accomplish the various fracturing/stimulation steps. For example, the steps of perforating the formation, fracturing the formation and flowing the treatment fluid out of the fracture back to the surface all typically require multiple trips of various downhole tools into and out of the well to complete. This can be very time consuming, especially when multiple pay zones are involved.
A number of solutions have been proposed to reduce the number of trips needed to fracture multiple zones in a multi-zone formation. In a number of these solutions, the fractures are formed starting at the bottom of the well and working upward. In one such method, the first fracture is initiated by perforating the formation in the first zone using a gun perforator that has been lowered into the well using a wireline. After the perforations have been formed, a tubing with a packer is lowered and set beneath the perforations. Then the fracture fluid is pumped down the annulus between the tubing and the casing or wellbore as the case may be. After the fracture has been formed, the packer is unset and the tubing raised to a location above the next zone to be fractured. Then the gun perforator is again lowered into the well adjacent to the region to be fractured to perforate that region. The gun perforator is again removed from the well using the wireline. Next, the tubing is lowered and the packer set between the perforated second zone and the fractured first zone. The fracture fluid is then pumped down the annulus into the second zone so as to fracture that zone. This process is repeated if additional zones need to be fractured. After all of the zones have been fractured then the fracture/stimulation fluid is produced. This solution saves a number of process steps by leaving the tubing in the well during the perforating and fracturing steps and by using a removable packer. However, it still requires multiple trips into and out of the well and thus allows for a substantial amount of imbibement to occur.
A number of solutions propose using a bottom-hole assembly (“BHA”), which combines the packer with a multi-stage perforating gun, which in turn is attached to a tubing string or jointed pipe. In one solution, the multi-stage perforating gun is detachably secured to the packer, which is disposed below the perforating gun. In another solution, the packer is attached above the multi-stage perforating gun. In the latter solution, a depth-control device may be incorporated into the BHA or at the surface to assist the well operator in accurately positioning the tool within the wellbore during perforation and fracturing.
The advantage of these solutions is that since the perforating gun is attached to the packer, the perforating gun does not have to be recovered at the surface between perforation steps. Therefore, a plurality of production zones can be perforated and fractured by a single run into the well in a continuous unbroken sequence, without withdrawing the tubing string, perforating gun or packer from the well before all the zones have been perforated and treated. A drawback of this solution, however, is that it does not allow flow back of the hydraulic fracture/stimulation treatment fluid in the multiple zones until after all of the zones have been perforated and fractured. Accordingly, this solution is subject to a certain amount of undesirable imbibement.
Therefore, it is desirable to be able to perforate and fracture multiple production zones in the formation while simultaneously flowing back previously placed hydraulic fractures/stimulation treatment fluids in zones that have already been perforated and fractured all in a single trip. The assignee of the present invention has carried out such a method using a top-down approach, i.e., by perforating and fracturing zones in a sequence starting at a location up hole and working toward the bottom of the well. The tool employed in this method was a BHA having an expandable packer connected to a tubing string, a centralizer connected to the packer, a hydra jetting sub connected to the centralizer and a ball sub connected to the hydra jetting sub, such as the one illustrated in FIG. 1A.
The assignee's prior method is carried out in the following sequence. First, Zone 1 is perforated using the hydra jetting sub, then it is fractured, and then the BHA is moved downhole toward Zone 2 washing down the wellbore in the process, as shown in FIG. 1A. Next, a ball is circulated down the tubing until it reaches the ball sub, as shown in FIGS. 1B and 1C. Once the ball has landed, the fluid exits the jets in the hydra jetting sub to thereby perforate Zone 2, as shown in FIG. 1C. Once Zone 2 has been perforated, the ball is circulated back up the tubing to the surface using the pressure from the formation, as shown in FIG. 1D. Next, the BHA is moved up hole and the packer is set just below Zone 1, as shown in FIG. 1E. Then the fracturing fluid is pumped down the tubing into the perforations in Zone 2 causing Zone 2 to fracture, as shown in FIG. 1E. The previously placed fracture fluid from Zone 1 is simultaneously recovered up the annulus. Next, the BHA is moved downhole toward Zone 3 washing down the wellbore in the process, as shown in FIG. 1F. The BHA is then moved downhole so that the hydra jetting tool is adjacent to Zone 3. The ball is again landed in the ball sub, and then fluid in pumped through the hydra jetting tool to perforate Zone 3, as shown in FIG. 1G. The process continues until all of the desired zones have been perforated, fractured and had their fracturing fluid flowed back to the surface.
The assignee's prior method of simultaneously perforating, fracturing and flowing back multiple zones in a subterranean formation overcomes many of the disadvantages of prior fracturing methods and has proven to be a useful method for treating multiple zones in a subterranean formation in the Northeastern United States. There are some formations, however, where the top-down fracturing method is less than desirable, for example, those found in the United States and Canadian Rockies. Furthermore, top down fracturing has several drawbacks.
The top down completion method requires the fracturing fluid to be pumped down the tubing which results in a larger ID tubing being needed to facilitate the flow rates needed to fracture the reservoir. A drawback of using larger pipe (2.375-2.875 inch diameter) is that it is relatively difficult to handle in the wellbore compared to smaller pipe sizes (1.5-2.0 inch diameter) and is more expensive. Also, in the top down method, the previously placed fracturing fluid is produced up the annulus, which impinges against the tubing string and therefore can cause damage to the tubing string. Furthermore, in the top down method the previously fractured zones are above the packer and flowing these zones back may result in proppant building up on the top of the packer. Additionally, top down completions diminish the annular pressure and mechanical integrity, which can greatly compromise future recompletion efforts.
It is therefore desired to have a bottom-up method of simultaneously perforating, fracturing and flowing back multiple zones that overcomes some of the drawbacks of the assignee of the present invention's prior treatment method.